The embodiments of the present invention relate generally to methods for determining pressure gradients in a wellbore. More specifically, the embodiments relate to methods for determining formation pressure gradients using multiple pressure readings from different depths in the wellbore.
Due to the high costs associated with drilling and producing hydrocarbon wells, optimizing the performance of wells has become very important. The acquisition of accurate data from the wellbore is critical to the optimization of the completion, production and/or rework of hydrocarbon wells. This wellbore data can be used to determine the location and quality of hydrocarbon reserves, whether the reserves can be produced through the wellbore, and for well control during drilling operations.
Well logging is a means of gathering data from subsurface formations by suspending measuring instruments within a wellbore and raising or lowering the instruments while measurements are made along the length of the wellbore. For example, data may be collected by lowering a measuring instrument into the wellbore using wireline logging, logging-while-drilling (LWD), or measurement-while-drilling (MWD) equipment. In wireline logging operations, the drill string is removed from the wellbore and measurement tools are lowered into the wellbore using a heavy cable that includes wires for providing power and control from the surface. In LWD and MWD operations, the measurement tools are integrated into the drill string and are ordinarily powered by batteries and controlled by either on-board and/or remote control systems. Regardless of the type of logging equipment used, the measurement tools normally acquire data from multiple depths along the length of the well. This data is processed to provide an informational picture, or log, of the formation, which is then used to, among other things, determine the location and quality of hydrocarbon reserves. One such measurement tool used to evaluate subsurface formations is a formation tester.
To understand the mechanics of formation testing, it is important to first understand how hydrocarbons are stored in subterranean formations. Hydrocarbons are not typically located in large underground pools, but are instead found within very small holes, or pore spaces, within certain types of rock. The ability of a rock formation to allow hydrocarbons to move between the pores, and consequently into a wellbore, is known as permeability. The viscosity of the oil is also an important parameter and the permeability divided by the viscosity is termed “mobility” (k/μ). Similarly, the hydrocarbons contained within these formations are usually under pressure and it is important to determine the magnitude of that pressure in order to safely and efficiently produce the well.
During drilling operations, a wellbore is typically filled with a drilling fluid (“mud”), such as water, or a water-based or oil-based mud. The density of the drilling fluid can be increased by adding special solids that are suspended in the mud. Increasing the density of the drilling fluid increases the hydrostatic pressure that helps maintain the integrity of the wellbore and prevents unwanted formation fluids from entering the wellbore. The drilling fluid is continuously circulated during drilling operations. Over time, as some of the liquid portion of the mud flows into the formation, solids in the mud are deposited on the inner wall of the wellbore to form a mudcake.
The mudcake acts as a membrane between the wellbore, which is filled with drilling fluid, and the hydrocarbon formation. The mudcake also limits the migration of drilling fluids from the area of high hydrostatic pressure in the wellbore to the relatively low-pressure formation. Mudcakes typically range from about 0.25 to 0.5 inch thick, and polymeric mudcakes are often about 0.1 inch thick. On the formation side of the mudcake, the pressure gradually decreases to equalize with the pressure of the surrounding formation.
In a typical formation testing operation, a formation tester is lowered to a desired depth within a wellbore. The wellbore is filled with mud, and the wall of the wellbore is coated with a mudcake. Because the inside of the tool is open to the well, hydrostatic pressure inside and outside the tool are equal. Once the formation tester is at the desired depth, a probe is extended to sealingly engage the wall of the wellbore and the tester internal flowline is isolated from the wellbore by closing one or more equalizer valves.
After the probe is extended and the flowline isolated, a small cylinder that is in communication with the flowline is drawn back to increase the total flowline volume. This causes the pressure within the flowline to decrease substantially below formation pressure. Then fluid contained with in the pore space of the rock adjacent to the probe is drawn into the flowline of the tool and the pressure increases to nearly formation pressure. The formation tester flowline in then in fluid communication with the formation and a pressure sensor can monitor the pressure of fluid in flowline over time. This process is known as a pretest. From this pressure versus time data, the pressure and permeability of the formation can be determined. Techniques for determining the pressure and permeability of the formation from the pressure versus time data are discussed in U.S. Pat. No. 5,703,286, issued to Proett et al., and incorporated herein by reference for all purposes.
Determining an accurate formation gradient is another one of the principle applications for formation testers. Methods for determining the formation gradient have performed several formation tests at different depths within the well. These methods often involve relocating the testing tool several times during the procedure. It has been proposed that by using a multi-probed tester with at least two widely spaced probes an improved formation gradient can be obtained at a single testing depth.
The primary advantage to using a multi-probed tester is that by using the fixed distance between the probes the accuracy could be improved, reducing the number of tool movements and potentially saving rig time. This method of multi-probed testing is not as straightforward as it might appear. One method of multi-probed testing is discussed in U.S. Pat. No. 4,860,580, issued to DuRocher, which is hereby incorporated by reference herein for all purposes. Other multi-probed formation testing methods are described in co-owned pending U.S. patent application Ser. No. 10/254,310, which is hereby incorporated by reference herein for all purposes.
In formation testing, the pressure gauge (typically a high accuracy quartz gauge) measures the pressure from the probes plus the pressure differential from the probe to the gauge. This pressure differential is related to fluid density of the fluid in the flowline. In conventional, single probe testing it is assumed that the effect of tester flowline density on pressure readings can be neglected because the flowline density does not change between pressure tests.
Now consider two probes spaced more than 10 ft apart. In this case, there is a different pressure differential for each probe due to the flowline fluid density and each probe spacing. Because one probe is a significantly greater distance from the pressure gauge, the differential pressure effect on each probe is significantly different. If this effect is not accounted for, the gradient determined by the multi-probed measurement will need to be corrected.
Thus, there remains a need in the art for methods of performing multi-probed formation testing that take into account the change in differential pressure due to the distance between the probes. Therefore, the embodiments of the present invention are directed to methods for calculating pressure gradients in multi-probed formation testers that seek to overcome the limitations of the prior art.